1. Technical Field
This disclosure relates to data received by borehole seismic directional receivers and data such as vertical seismic profile (VSP) data. Still more specifically, this disclosure relates to a method for estimating the orientation of a multi-component (3C) directional receiver deployed in vertical or deviated boreholes.
2. Description of the Related Art
In recent years, offshore exploration and development of hydrocarbon reserves has been conducted at increasingly deeper depths of water. As the water depths increase and the boreholes lengthen, recovery of formation fluids from subterranean formations becomes increasingly difficult and complex. However, rigorous analysis of subterranean formations has led to more efficient oil and gas recovery and vertical seismic profile (VSP) surveys have emerged as an important tool for analyzing subterranean formations so that the hydrocarbon fluids in the formations can be more efficiently recovered.
VSPs are a class of borehole seismic measurements used for correlation between surface directional receivers and wireline logging data. VSPs can be used to tie surface seismic data to borehole data, providing a useful tie to measured depths. Typically, VSPs yield higher resolution data than surface seismic profiles provide. VSPs enable the conversion of seismic data to zero-phase data, and distinguish primary reflections from multiple reflections. In addition, VSPs are often used for analysis of portions of a formation ahead of the drill bit.
VSPs are seismic measurements made in a borehole using one or more downhole receivers and a seismic source at the surface near the wellsite. VSPs can vary in well configuration, such as the number and location of sources and receivers, and how the sources and receivers are deployed. Conventional VSPs use a surface seismic source, which is commonly a vibrator on land, or an air-gun in marine environments. More recent offshore techniques involve the use of a seismic source placed at the ocean floor and spaced away from the borehole.
When using a non-gimbaled multi-component receiver, seismic waves are received relative to the orientation of the seismic receiver and measured on a coordinate system specific to the seismic receiver. For example, a three component (3C) receiver measures received seismic waves on three orthonormal axes. Typically, however, it is desirable to interpret the measured seismic data in another coordinate system, such as a true earth frame (northing, easting, vertical). Thus, data received relative to the coordinate system of each non-gimbaled receiver requires rotation to the desired coordinate system for subsequent use.
Referring to FIG. 1, a general illustration is shown of a VSP survey 10 being conducted on a deviated well or borehole 11. A seismic source 12a, 12b, 12c or 12x, depicted in FIG. 1 as being on the surface generates a seismic signal to be detected by the downhole directional receiver 13 that is non-gimbaled. The seismic sources 12a, 12b, 12c and 12x are illustrative of a plurality of seismic generators placed at various azimuths around the borehole 11. The borehole 11 has a deviated portion 14 that deviates from a true vertical axis Z at an angle i. The directional receiver 13 is shown deployed along the deviated portion 14 of the borehole 11. The directional receiver 13 is coupled to the low side 15 of the borehole 11 by a decentralizer 17 for receiving seismic signals generated from the seismic source 12a, 12b, 12c or 12x 12 on the surface 16. As shown in FIG. 1, the longitudinal axis Pz of the directional receiver 13 is oriented at an angle i from the true vertical axis Z. Therefore, in addition to the angle i, to properly orient the directional receiver 13 in an XYZ coordinate system where Z is true vertical, the relative bearing angle Ω of the directional receiver 13 (see FIGS. 2A-2B) needs to be determined. For a deviated borehole like the one shown at 11 in FIG. 1, the relative bearing angle Ω is the angle between the X-axis of the directional receiver 13 in the X-Y plane and the local vertical plane that passes through the well axis (or the longitudinal axis Pz of the receiver 13) and true vertical Z as explained below in connection with FIGS. 2A-2B.
One method of determining the relative bearing angle is presented by Becquey and Dubesset in their paper entitled Three-Component Sonde Orientation in a Deviated Well, Geophysics, vol. 55, no. 10 (1990) which provides a more refined method. The method is ambiguous in that two possible relative bearings are calculated and determination of which is the correct relative bearing requires additional information or physical considerations.
FIG. 2A illustrates a method of determining the relative bearing angle that is disclosed in commonly assigned U.S. Pat. No. 6,922,373, which is incorporated herein by reference. A coordinate system ray diagram describes the geometric relationship between a non-gimbaled directional receiver 13 and a borehole 11 (FIG. 1). The three orthonormal axes of a directional receiver like the one shown at 13 in FIG. 1 are P1, P2, and PZ, where PZ is the axis corresponding to the longitudinal axis of the directional receiver 13 in the deviated portion 14 of the borehole 11. The receiver plane 19 is defined by the P1 and P2 transverse axes and the plane 19 is normal to the longitudinal axis PZ. The preferred coordinate system X, Y, and Z is also shown in FIG. 2A, where Z is true vertical and the transverse or horizontal plane 21 is defined by the X and Y components. Orientating the P-wave arrival 18 into the preferred X, Y, and Z coordinate system requires either a full 3C rotation through the relative bearing angle Ω, or a dividing the 3C rotation into two parts.
If the 3C rotation is split into two parts, one procedure is as follows: rotate through the relative bearing angle in the tool x-y (P1-P2) plane to give a new X and Y, where Y is horizontal and X′ is in the local vertical well plane as shown in FIG. 2B; and rotate X′ and PZ through well deviation angle i (about Y) to give the final X and Z components. To perform either procedure, the relative bearing angle Ω must be known.
FIG. 2B further illustrates that the relative bearing angle Ω is in the X-Y plane 19 of the tool 13 and is the angle Ω between P1 or X in the X-Y plane 19 and the local vertical plane that passes through the borehole 11 (represented by the vertical line Z′ through the center). Therefore, rotating the P1(X) and P2 (Y) component data through the relative bearing angle Ω, the rotated X′ is in the local vertical plane of the borehole and the rotated Y′ is horizontal (see also FIG. 2A). The '373 patent discloses a multi-step process for calculating the relative bearing angle Ω that includes: (1) estimating the relative bearing angle Ω using an approximate angle retrieved from a relative hearing sensor or other reasonable estimation method; (2) scanning angles of +/−25° around the estimated relative bearing angle Ω, and for each scanned angle, (a) rotating seismic receiver data into the true earth frame (east, north, vertical) using the angle from the relative bearing sensor, (b) measuring the polarization angle α of the rotated data in the horizontal plane 21, (c) calculating the azimuth error using a function of the form:
  azimerr  =            ∑              s        =        1            m        ⁢                  1                  N          s                    ⁢                        ∑                      t            =            1                                N            s                          ⁢                                                      lin              t                        ⁡                          (                                                α                  t                                -                                  azim                  s                                            )                                                    
where the function represents a weighted sum (lint=hodogram linearity) of the differences between the source azimuth (azims) and the estimated azimuth from the polarization (αt). The summation is performed over all shots (t) for a particular seismic source 12a, 12b, 12c or 12x (FIG. 1) and then noimalized by the number of source events (Ns) for that source to give an equal contribution from all m sources; and (3) selecting the relative bearing angle closest to the measured relative bearing sensor angle that minimizes the local azimuth error.
While the above method works well for multi-azimuth surveys, it is still subject to errors caused by geological complexity and in certain circumstances, systematic errors in the estimated relative bearing angle Ω may be present. Accordingly, a more effective method of determining the relative bearing angle Ω of a non-gimbaled directional receiver 13 in a borehole 11 is needed.